Okon, Anietie N. (Department of Chemical & Petroleum Engineering, University of Uyo, Nigeria) | Udoh, Francis D. (Department of Chemical & Petroleum Engineering, University of Uyo, Nigeria, Department of Chemical & Petroleum Engineering, Afe Babalola University, Nigeria) | Appah, Dulu (Department of Gas Engineering, University of Port Harcourt, Nigeria)
Several correlations have been developed to predict wellhead pressure–production rate relationship in the Niger Delta region. Regrettably, most of these correlations were developed from field data that are not from the Niger Delta region and with limited field test data ranges, so their predictions are lower than expected field values when applied to the Niger Delta. Additionally, some developed wellhead pressure–production rate correlations based on Niger Delta field data are made using in-house equations by the operating companies in the Niger Delta region. To ameliorate this anomaly, sixty four (64) field test data: choke size (S), production rate (q), gas-liquid ratio (GLR), flowing wellhead pressure (Pwh), flowing temperature (FTHP) and basic sediment and water (BS&W) were collected from oil producing wells in the Niger Delta region to develop wellhead pressure–production rate correlations based on Gilbert correlation and modified Gilbert equations. The developed correlations using Niger Delta field test data were compared with several authors' correlations. The results obtained indicate that the developed correlations resulted in better predictions than earlier correlations. In addition, the statistical analysis of the developed correlations used to ascertain the extent of their predicted values differ from the field test data and resulted in average error, absolute error and standard deviation of -0.1477, 0.4430 and 0.9582 for Gilbert formula and -0.2515, 0.4737 and 1.0997 for modified Gilbert formula, respectively. Furthermore, the developed correlations are comparable with an average correlation coefficient of 0.9869. Therefore, the developed correlations can be used as a quick tool to estimate the wellhead pressure–production rate relationship in Niger Delta oil fields.
Andersen, Niels (National Space Institute – DTU Space & Polar DTU) | Bekker, Pieter (University of Dundee and Steptoe & Johnson LLP) | Bishopp, David (Galp Energia) | Nassif, Toufic (Sonde Resources Corporation) | Nordentoft-Lauridsen, Sune (National Space Institute & Polar DTU) | van de Poll, Robert (Fugro N.V.)
This paper provides an overview of the history of global maritime boundary issues, mechanisms to resolve boundary disputes, and the economic potential that can be unlocked by coastal States through the exploitation of hydrocarbons trapped in areas currently unavailable for exploration and production operations.
Vast hydrocarbon reserves are tied up in areas, either underlying waters greater than 200 nm offshore or disputed by coastal States. In the former case technology in the form of deepwater drilling has made testing the potential feasible, whilst in the latter case many of the 311 or so areas in dispute are able to be tested and developed using conventional techniques.
Anything that appears to show a sovereign entity ceding control of land or sea to another country inevitably takes on a high profile in the countries concerned, which in the worst case can lead to armed conflict. It is a credit to those States that subscribe to the principles of the United Nations Charter and the United Nations Convention on the Law of the Sea ("UNCLOS") that they have reached agreement on how the economic potential trapped in disputed areas may be divided or shared.
High-profile, high-stakes disputes relating to offshore oil and gas deposits underscore the importance of the modern law of the sea, and international law generally, to the peaceful settlement of boundary disputes affecting the energy industry. Yet boundary disputes form an overlooked area of investment risk management in the energy sector.
This paper will introduce the technical and legal principles behind the solutions reached by States and will highlight some of the areas with the greatest hydrocarbon potential that have yet to be exploited as well as the areas of risk that require mitigation before investors will advance risk capital.
Flow-rate prediction of oil production wells is of prime importance to effectively confront high-water-cut and separator problems. (Semi-) empirical multiphase-flow correlations are proved quite useful for this purpose. This work presents new generalized multiphase flow choke correlation, derived on the basis of actual production data from horizontal and vertical wells from an oil field in Iran. The newly established correlation predicts liquid flow rates as a function of flowing wellhead pressure, gas/liquid ratio, surface wellhead choke size, and the newly incorporated parameters: basic sediment and water (BS&W) and temperature. To evaluate the influence of these two new parameters, a parameter-sensitivity analysis was performed and the results are shown. This proposed correlation exhibited an average error of roughly 2.89%, which is superior to those previous correlations in the literature that did not use these two newly incorporated parameters (BS&W and temperature). These new parameters can be added to the previous correlations when the water cut and temperature become important in the production history of the wells.
The phenomenon of multiphase flow (liquid and gas) happens in the wellhead of the majority of the producing wells. As the regulation of the flow rate becomes important during the production period in the producing wells, chokes are used for isolating the underground reservoir from pressure variations in the surface equipment, and also they are used for preventing or reducing the water production. Larger amounts of produced water from oil recovery result in increasing of operating costs and are a major environmental concern for oil production (Jin and Wojtanowicz 2010).
Although numerous multiphase-flow correlations are included in the literature (Al-Attar 2010), almost all of them are limited to a special operational condition in which the correlations are driven. As a result, the strength of those correlations for predicting the actual flow rate is restricted.
Gilbert (1954) developed the most popular multiphase flow surface choke correlation, but this correlation is valid for the critical flow condition when the upstream pressure of the choke is 70% or more higher than the downstream pressure (Ghareeb and Shedid 2007).
Flow through the wellhead chokes is mainly divided into two critical and subcritical conditions. Within this manuscript, the critical-flow condition refers to the state at which the flow rate reaches a maximum amount independent of the downstream and upstream pressure difference of the choke. Empirical correlations are mainly used for critical-flow condition.
Amari, Mustafa (Schlumberger) | Misherghi, Nasser Ali (Schlumberger) | Algdamsi, Hossein Ali (Schlumberger) | Sharaf, Hosam Eldin Mohamed (Schlumberger) | Abid, Mohamed (Schlumberger) | Porturas, Francisco (Schlumberger) | Zeglam, Adel (Mellitah Oil & Gas B.V Libya) | Jalool, Hassan (Mellitah Oil & Gas B.V Libya)
With the advances made in drilling long horizontal wells over the past decades it has become economically attractive to produce oil from thin oil rims. However, the production from these types of reservoirs presents several challenges. Gas coning is one of the most important ones. Horizontal well drilling traditionally helps to improve the oil recovery and avoid problems of premature gas/water breakthrough. In Bouri field, offshore Libya, the main concern of the operator was to establish an advanced method of controlling gas and water encroachment in a fractured carbonate reservoir characterized by high vertical permeability. This paper describes the first Inflow Control Device (ICD) installation for Mellitah Oil & Gas, and the first such application in Libya Offshore field. It was an integral part of a well completion aimed at evenly distributing inflow in a horizontal well, and at limiting the negative effects after occurrence of expected gas breakthrough. Due to small clearances involved, the ICD deployment presented a significant operational challenge. Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency .Swelling-packers were used to compartmentalize the horizontal and build sections, allowing better drawdown control and eliminating cross-flow issues. The completion required re-thinking of the established acid-wash treatment procedures, ultimately improving the overall well clean-up. Integrated analysis methods using steady-state wellbore hydraulic and 3D dynamic simulators were performed to generate flow profiles and calculate ICD pressure drop along the horizontal section. The models were updated using results from logging-while-drilling (LWD) and with real-time modifications to the initial design.
To verify the inflow profile along the length of the ICD completion, production logging (PLT) was conducted. The inflow profiles compared favorably with those predicted by the models.
Amari, Mustafa (Schlumberger) | Porturas, Francisco (Schlumberger) | Algdamsi, Hossein Ali (Schlumberger) | Sharaf, Hosam Eldin Mohamed (Schlumberger) | Lakhdar, Mohamed (Schlumberger) | Misherghi, Nasser Ali (Schlumberger) | Grivet, Marcel (Mellitah Oil&Gas) | Borac, Srdjan (Mellitah Oil&Gas) | Jalool, Hassan (Mellitah Oil&Gas) | Vegliante, Enzo (Mellitah Gas BV) | Rossi, Luciano (Mellitah Oil&Gas)